Producible accumulations of hydrocarbon reserves occur when hydrocarbons generated from source rock migrate through the subterranean to a trap where they are accumulated. Reservoir rock that once contained high oil saturation is generally referred to as a ‘paleo oil zone’ and traces of remaining oil are known as ‘oil shows’ or ‘residual oil’. Paleo oil zones sometimes indicate proximity to oil accumulations. Detecting current oil zones or paleo oil zones while drilling can aid decision making. For example, detecting a paleo zone may prompt additional testing that would not have been made without detection. If paleo zones can be detected quickly a well could be drilled to locate a current oil accumulation in proximity to the first drill site.
Existing techniques that detect paleo oil zones may also detect current oil zones. Also, detection of oil accumulation and migration in the geological past is critical for the evaluation of wells during exploration. During and after drilling a well, there are a number of ways of detecting whether rocks are currently oil saturated, or have been oil saturated. These include detecting the concentration and composition of gas in drilling fluids using gas chromatography; visual inspection; ‘wireline’ logging; measuring while drilling (MWD); logging while drilling (LWD) or the like to detect changes in properties of rocks and fluids. Most of these techniques are too expensive or complicated to implement on every exploration well. Also, these methods cannot always detect residual oil, particularly if its concentration is beneath the limit of detection (LoD) of the measuring device. LWD tools and measurements are expensive, and involve adding tools to the drill stem and sending them ‘down-hole’ to measure characteristics like resistivity, pressure, gamma radiation, density, porosity, water saturation and so on. Testing of this kind is often undertaken before making expensive decisions about well completion. However, a more detailed chemical analysis would aid in the characterisation of the geological formation.
Accordingly, analysis of drilling fluids and rock cuttings is of value during exploration and production of hydrocarbons. At present, drilling fluid (or ‘mud’) is frequently analysed for dissolved gases in a process known as ‘mud gas logging’. Samples are extracted from the returning mud and subsequently analyzed for chemical composition by chromatographic or spectroscopic means such as infrared absorption (IR); gas chromatography (GC); mass spectrometry (MS); or gas chromatography and mass spectrometry (GC-MS).
The use of MS and GC-MS provides richer information about chemical composition, and has permitted studies of carbon isotopes for geochemical purposes. Typically, GC-MS analysis has been carried out using large, expensive and power hungry instruments located in central laboratories often remote from well-sites. The turn-around for analysis of drilling mud and cuttings by GC-MS would be of the order of two to four weeks from sample collection to delivery of a report on chemical composition—often too late to have an impact on drilling decisions with a high opportunity cost such as geo-steering, well testing or well completion.
One disadvantage of commercially available well-site GC and GC-MS technology is that it is limited to detecting low carbon number hydrocarbons (e.g. C1 to C5). Geochemists are increasingly interested in detecting heavier compounds outside the ‘bandwidth’ of today's mud gas logging instruments. Free organic matter (i.e. Bitumen) in rocks, drilling mud or rock cuttings is a highly complex mixture that contains a rich variety of compounds including alkanes, aliphatics and aromatics. Measuring all of these compounds provides geochemists with valuable information about formation origin, age and thermal maturity. For example, lower molecular weight alkanes (i.e. <C21) are derived from algae and bacteria, whereas higher molecular weight homologs (e.g. C22-C33) are derived from plant waxes. Furthermore, odd-dominate alkanes indicate immature organic matter and a loss of the odd dominance reveals that bitumen is in the oil window. Similarly, aliphatic-rich material is derived from marine shales containing algae remains, whereas more polar matter is derived from land plant remains. Steranes are found in aliphatic fractions and were once components of cell membranes. Steranes are source specific: C27 steranes are produced by algae; C29 steranes are produced by land plants and C28 steranes are prevalent in lacustrine (i.e. fresh water) environments. The ratio of C28 steranes to C29 steranes is used as an age indicator, and the prevalence of the 20S over the 20R sterane isomers gives an indication of thermal maturity. Likewise, hopanes are found in aliphatic fractions and prevalence of the 22S over the 22R isomer gives an indication of thermal maturity.
Detecting these substances and measuring their relative concentrations and other characteristics is important during exploration and production in order to identify source rocks in a formation and determine whether or not they bear materials that may be in the ‘oil window’. Today, the analytical tools with sufficient performance to resolve and identify ‘marker’ compounds from aromatic, aliphatic and polar fractions are only available in central laboratories. Due to their large size, weight and infrastructure overhead it would not be feasible to deploy them at the well-site. Accordingly there is a need for an improved, portable analytical tool.